Measurement and control system for a downhole tool

ABSTRACT

A system and method of measuring and controlling the operation of a downhole steam generator. The system may include surface and/or downhole control systems for sending and/or receiving control and measurement signals. The control systems may also communicate with and control surface and/or downhole equipment for supplying process fluids, gasses, and/or mixtures to the downhole steam generator. The control system may control operation of the downhole steam generator by storing, processing, and/or analyzing measured data corresponding to one or more downhole steam generator operations and/or one or more field, formation, reservoir, or other operating objective.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. Patent Application Ser. No.61/737,570, filed Dec. 14, 2012, the contents of which are hereinincorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the invention relate to a measurement and control systemfor a downhole tool. In particular, embodiments of the invention relateto a system for measuring the operational characteristics of a downholesteam generator, controlling the operation of the downhole steamgenerator, and performing diagnostic operations.

2. Description of the Related Art

The general configuration of the surface provision of fuel, oxidants,and water to a downhole steam generator are known. There are, however,serious technical difficulties connected to the ignition, combustion,and production of steam from downhole steam generators due to the manyinteracting physical processes involved. Such physical processes includebut are not limited to operating pressures, operating temperatures,downhole remoteness, feed line delays, and acoustic feedback.

Generally, downhole steam generators may have systems at the surface forproviding fuel, oxidant, and water to the wellhead. These systems,however, are not only remote to the downhole steam generator, but do notprovide a means for feedback into the control loop the actual measuredperformance at the downhole steam generator. In essence, these systemsare essentially controlled by an “open loop” control system whereinthere is no measurement of the system's downhole output that can be usedto adjust the system's operational parameters and thus adjust thesystem's downhole output or performance. Previous configurations ofdownhole steam generators did not use or need measurement and controldownhole at the downhole steam generator.

There is now a need for new measurement and control systems for downholesteam generators.

SUMMARY OF THE INVENTION

Embodiments of the invention include a measurement and control systemthat comprises a downhole tool, such as a downhole steam generator; anda (surface and/or downhole) control unit that functions to receive ameasurement signal from the downhole tool, wherein the control unitfunctions to control operation, output, and/or performance of thedownhole tool in response to the measurement signal. This may be thefeedback and control loop for a single well DHSG system, for example.The measurement signal may contain information related to theconfiguration, output, and/or performance, etc. of the downhole,wellhead, and/or surface equipment.

Embodiments of the invention include a measurement and control systemthat comprises a downhole tool, such as a downhole steam generator; anda (surface and/or downhole) control unit operable to receive oilfielddata, wherein the control unit is operable to control operation of thedownhole tool in response to the oilfield data.

Embodiments of the invention include a method of operating a measurementand control system that comprises measuring and/or monitoring anoperational characteristic of a downhole tool, such as a downhole steamgenerator; communicating and/or receiving a measurement signalcorresponding to the operational characteristic; and controllingoperation of the downhole tool using a control unit in response to themeasurement signal.

Embodiments of the invention include a measurement and control systemthat comprises a master control unit that functions to receive oilfielddata; a plurality of surface control units in communication with themaster control unit, wherein each surface control unit controlsoperation of a downhole steam generator (DHSG), and wherein the mastercontrol unit is operable to control operation of the DHSGs via remotesetpoint adjustments to each surface control unit in response to theoilfield data. The remote setpoint adjustments may be continuouslyvariable. The master control unit may be an oilfield master controllerthat controls one or more individual well surface and/or downholecontrol units, which control the operation of one or more downhole steamgenerators.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the inventioncan be understood in detail, a more particular description of theinvention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 illustrates a measurement and control system for a downhole steamgenerator according to one embodiment.

FIG. 2 illustrates a measurement and control system for a downhole steamgenerator according to one embodiment.

FIG. 3 illustrates a measurement and control system for a downhole steamgenerator according to one embodiment.

FIG. 4 illustrates a measurement and control system for a downhole steamgenerator according to one embodiment.

FIG. 5 illustrates a measurement and control system for a plurality ofsystems and downhole steam generators according to one embodiment.

DETAILED DESCRIPTION

Embodiments of the invention include a system for providing measurementand control of a downhole steam generator (“DHSG”). The DHSG may besupported from the surface by a wellhead. The system may providemeasurement and control of the DHSG at the surface and/or downhole. Thesystem may use a signal pathway from the DHSG to the surface wellhead.In addition to water, fuel, oxidizer, and/or ignitor lines between thewellhead and the DHSG, the system may include one or more signaltransmission lines for the measurement and control. The system describedherein provides the means for construction of a “closed loop” controlsystem where the operational parameters may be adjusted depending uponthe system's actual output and performance and the desired output andperformance. The closed loop control system may include manualintervention.

The measurement and control of surface and/or downhole equipment ordelivery equipment, such as pumps, compressors, valves, etc., and/orDHSGs may involve several subsystems which have reaction time delays,opportunities for oscillation, pressure losses, and flow constrictions.As such, the measurements and control requirements can be complex andhighly interactive. Therefore, the measurement and control systemembodiments described herein optimally serve the distribution system andits control architecture, wherein the interaction delays are minimizedby keeping the measurement and control within a localized system bysegmenting and isolating sections of the overall system into focusedsubsystems.

The measurement and control systems 100-500 described herein may includea control unit having programmable central processing units operablewith memory, mass storage devices, input/output controls, and/or displaydevices. The control unit may include support circuits such as powersupplies, clocks, cache, and/or input/output circuits. The control unitmay be operable to process, store, analyze, send, and/or receive datafrom sensors and/or other devices, and may be operable to control one ormore devices that are in (wired and/or wireless) communication with thesystems. The control unit may be configured with software/algorithmsthat process input signals/commands to generate output signals/commandsbased on an operational characteristic of the DHSG. The control unitsmay control the DHSG operation based on input/output and/orpre-programmed knowledge derived from reservoir/well analysis (a priorior real time) and/or the DHSG performance.

In one embodiment, the control unit may be and/or include an analog ordigital device that has a preprogrammed response upon receiving aparticular input. For example, one or more basis analog control devices,such as signal amplifiers, with simple analog input and analog responsemay be used with the measurement and control systems 100-500 describedherein. Another example is a bimetal thermostat for (at least partially)opening and closing an orifice within the measurement and controlsystems 100-500 described herein. Further examples include digitalcircuits and switches. Reduced command processors may be used to operatethese analog or digital devices. An input, such as a measurement, isreceived by the control unit or analog or digital device, and a responseis given by the control unit or analog or digital device to control(such as change) the operation of a DHSG. Numerous types of analog ordigital devices known in the art may be used with the measurement andcontrol systems 100-500 in both uphole and downhole operation.

Although the embodiments described herein relate to a DHSG, embodimentsof the invention may be used with any other types of downhole tools. Oneexample of a DHSG that may be used with the embodiments described hereinis shown and described as DHSG 10, 100 in U.S. Patent ApplicationPublication No. 2011/0127036, filed on Jul. 15, 2010. Another example ofa DHSG that may be used with the embodiments described herein is shownand described as system 1000 in U.S. Patent Application Publication No.2011/0214858, filed on Mar. 7, 2011. The contents of each of the abovereferenced patent application publications are herein incorporated byreference in their entirety.

FIG. 1 illustrates one embodiment of a measurement and control system100 for measuring the operational characteristics of and controlling theoperation of a DHSG 110. The system 100 may also measure and controlsurface equipment 140 used for supplying water, fuel, oxidant, ignition,and/or other process fluids, gasses, mixtures, and/or other processconsumables such as ignition power, to the DHSG 110. The DHSG 110 may besupported at the surface by a wellhead 130 via one or more umbilicals120. The umbilicals 120 may include one more conduits/lines forcommunicating process fluids, gasses, mixtures, and/or other processconsumables such as ignition power, to and from the DHSG 110, as well asone or more conduits/lines for communicating mechanical, electrical,and/or hydraulic signals to and from the DHSG 110.

The system 100 may receive and send signals directly to and from theDHSG 110. One or more measurement signals may be transmitted directly tothe system 100. One or more control signals may be directly wired intothe DHSG 110. In addition to water, fuel, oxidizer, and/or ignitor linesfrom the surface, one or more electrical signal transmission lines maybe included to communicate with the DHSG 110. The transmission lines maycarry analog and/or digital signals, and may use one or moretransmission methods or combination of transmission modes.

In one embodiment, one or more sensors may be placed at or near the DHSG110. The sensors may measure the operational characteristics orperformance of the DHSG 110, such as temperatures, pressures, flowrates, volumes, generation of steam, and/or the type, volume, quantity,and/or quality of any reactant/injectant materials, e.g. process fluids,gasses, mixtures, and/or other process consumables such as ignitionpower, flowing into and/or out of the DHSG 110. Process fluids, gasses,and/or mixtures may include, but are not limited to, water, steam, air,oxygen, carbon dioxide, hydrogen, nitrogen, methane, syngas,nanocatalyst, nanoparticles, fracturing materials, propants, and/or anyother materials that may positively or negatively affect a formation, areservoir within the formation, and/or hydrocarbons within thereservoir. Sensors may include, but are not limited to, pressure,temperature, flow, acoustic, electromagnetic, NMR, nuclear, density,and/or fluorescent detector sensors. In one embodiment, control valves,ignitors, glowplugs, motors, pumps and/or other constriction orexpansion devices may also be placed at the DHSG 110 to adjust itsperformance and ability to inject materials (such as steam and otherinjectants) into a reservoir. Process fluids, gasses, and/or mixturesmay be controlled by final control elements, which may be located at thesurface and/or downhole, and which may be passive or active (flowrestrictors), digital (on/off), and/or modulating proportional devices.

One or more measurement signals, originating from the DHSG 110, may betransmitted to the system 100 (1) directly via an electrical or opticalsignal in either analog or digital form; (2) indirectly to a subsurfacesubsystem where they are converted to electrical or optical signalingwhere they are then transmitted to the surface via analog or digitaltelemetry; and/or (3) by intelligent indirect transmission to thesurface with compression and multiplexing of information occurringdownhole prior to transmission via analog or digital telemetry usingoptical or electrical signaling.

One or more control signals, originating from the system 100, may betransmitted to the DHSG 110 (1) directly via analog or digital signalsto each or combined control mechanisms of the DHSG 110; (2) indirectlyvia analog or digital signals via electrical or optical signaling to anintermediate control system located downhole, such as nearby the DHSG110; and/or (3) by intelligent indirect transmission with compressionand multiplexing of information from the surface to an intermediatecontrol system located downhole, such as nearby the DHSG 110.

The system 100 may control operation of the DHSG 110 based on or inresponse to one or more measurement signals by changing the operationalcharacteristics and/or condition of one or more final control elements(which may be located at the surface and/or downhole), which in turnchange the state of the process fluids, gasses, and/or mixtures ofinterest at the DHSG 110. The system 100 may generate and transmit oneor more control signals to the DHSG 110 (or downhole system in controlof the DHSG 110) to control the operation of the DHSG 110. The system100 may control one or more components of the DHSG 110.

FIG. 2 illustrates one embodiment of a measurement and control system200 for measuring the operational characteristics of and controlling theoperation of a DHSG 210. The system 200 may receive performancemeasurements from the DHSG 210. In particular, a downhole system 215(such as a measurement interface) may receive sensor measurements fromthe DHSG 210 where they may be converted to digital form, averaged, fastFourier transformed (FFT), filtered and/or otherwise analyzed. Thisinformation may then be compressed or multiplexed and digitallytransmitted to the surface through the umbilical 220 and wellhead 230 tothe system 200. The system 200 may use this information to controlsurface equipment 240 and the materials and/or process fluids, gasses,and/or mixtures delivered to the DHSG 210 to adjust the operation of theDHSG 210. In one embodiment, there may not be any control systems orparameters adjusted downhole. The downhole system 215 packages thedownhole sensor information for transmission to the surface system 200.

FIG. 3 illustrates one embodiment of a measurement and control system300 for measuring the operational characteristics of and controlling theoperation of a DHSG 310. A downhole system 315, such as the measurementand control systems 100-500 described herein, may be local to the DHSG310 so as to reduce control reaction lag time, provide for multiple andprocessed performance measurements of the DHSG 310, and/or provide ameans for distributed control of the DHSG 310. The downhole system 315may be supported by umbilicals 320 that are connected to well head 330at the surface. Control signals may be generated by and transmitted fromthe surface system 300 to the downhole system 315 to control operationof the DHSG 310. Control signals may be generated by and transmittedfrom the downhole system 315 to the surface system 300 to controloperation of the DHSG 310. Measurement signals (such as sensormeasurements) may be processed and used by the surface system 300 and/orthe downhole subsystem 315. The control signals originating from thedownhole system 315 may be transmitted to the surface system 300 via oneor more transmission lines within or separate from umbilicals 320. Thesecontrol signals may serve as requests to the surface system 300. Thesurface system 300 may respond to the requests by changing the state ofone or more final control elements, which in turn change the state orcondition of the process fluids, gasses, and/or mixtures provided to orby the DHSG 310.

FIG. 3 illustrates ten measurement signals 1-10 and ten control signalsA-J communicated between the systems 300, 315 and DHSG 310. The DHSG 310may produce measurement signals 6-10, and may be controlled by controlsignals G-J. Measurement signals 6 and 7 are transmitted to the surfacesystem 300, while measurements signals 8-10 are processed by thedownhole system 315 (and may not be transmitted to the surface).Measurement signals 4 and 5 may be generated by the downhole system 315(and may derived from signals 8-10 and others) and may be transmitted tothe surface system 300. Similarly, control signal G from the surface maybe directly transmitted to the DHSG 310 by the downhole system 315. Thedownhole system 315 may synthesize control signals H-J from the controlssignals E-G from the surface system 300.

In one embodiment, a portion of the control system for the DHSG 310 isplaced within the downhole system 315. All, a portion, or none of themeasurement signals are sent to the surface system 300, and, similarly,all, a portion, or none of the control signals are generated by thedownhole system 315. The downhole control may be implemented within thedownhole system 315 by any combination of analog or digital electroniccircuitry. Analog circuitry includes, but not limited to, analogfilters, comparators, amplifiers, current loop drivers, etc. Digitalcircuitry includes, but not limited to, D-A, A-D conversion, digitalsignal processors, control CPUs, microcontrollers, FPGA's, etc.

In one embodiment, control signals from the surface system 300 may beinterpreted by the downhole system 315, which then drives one or morecontrol processes of flow, pressure, ignition, injection, etc. viaelectrical signals to control valves, igniters, etc. of the DHSG 310.Similarly, measurement signals of the DHSG 310 performance will feedback into the downhole system 315, and may be used within the downholesystem 315 control loop. The downhole system 315 may send measurementsand control requests to the surface system 300.

In one embodiment, the system 300 includes a control architecture, whichconsists of shared information spaces and distributed or layered controlinteraction mechanisms. The surface system 300 may pass control signalsto the downhole system 315, which, in turn, determines settings for oneor more local performance control parameters dependent upon sensormeasurements. In this manner, the closed loop control for the downholesystem 315 and DHSG 310 is completely downhole and only informationalmeasurements of performance are transmitted up-hole.

FIG. 4 illustrates one embodiment of a measurement and control system400 for measuring the operational characteristics of and controlling theoperation of a DHSG 410. The DHSG 410 and a downhole system 415, such asmeasurement and control systems 100-500 described herein, may besupported by umbilicals 420 that are connected to well head 430.Measurement information or other oilfield data from one or more wells inthe same and/or surrounding fields may be used to set the operatingparameters of the DHSG 410. The measurement information or otheroilfield data may be communicated to the surface system 400 to determineand control the operating parameters of the DHSG 410, such as bycontrolling the output of surface equipment 440 supplying processfluids, gasses, and/or mixtures to the DHSG 410, or by modulatingexternal set points or parameters of one of the measurement and controlsystems 100-300 described herein.

In one embodiment, the various measurements from the surrounding fieldmay be used to set the desired operation of the DHSG 410. Theinteraction between the DHSG 410, and if applicable other adjacent ornearby DHSG's, and the reservoir or formation is monitored, and theresults are used to adjust the desired operating setpoints andperformance levels and control of the DHSG 410. The measured fieldinformation may be input into a specific, complex model (within thesystem 400) for the field and its interaction with the DHSG 410. Fromthis model, the required setpoints of the DHSG 410 may be determined toachieve the desired performance of the injection well. The resultingimpact on the reservoir or formation by the DHSG 410 may be measured,and this information may be feed back into the model to determine thereal-time setpoints for the operating parameters of the DHSG 410.

FIG. 5 illustrates one embodiment of a measurement and control system500 for measuring the operational characteristics of and controlling theoperation of one or more DHSGs 510 a, 510 b. The master system 500 maycontrol, monitor, and/or coordinate the operation of multiple surfacemeasurement and control systems 500 a, 500 b, downhole systems 515 a,515 b, and thus DHSGs 510 a, 510 b from a central control point. Themaster system 500 may use measurement information or other oilfield datafrom one or more wells 1-N in a field. The DHSGs 510 a, 510 b and thedownhole systems 515 a, 515 b, such as measurement and control systems100-500 described herein, may be supported by umbilicals 520 a, 520 bthat are connected to well heads 530 a, 530 b.

The master system 500 may thus control directly or indirectly one ormore of the DHSGs 510 a, 510 b, such as by controlling the output ofsurface equipment 540 a, 540 b, which may be the same equipment forsupplying process fluids, gasses, and/or mixtures to the DHSGs 510 a,510 b. The master system 500 “orchestrates” multiple DHSGs, and may use,in addition to information coming from each DHSG, additional informationrelated to the overall field, formation, and/or reservoir and resultingaffects of the one or more DHSGs. This additional information may be aset programmed sequence of DHSG on/off and other control options. Thisadditional information may be measurements made within the field thatwould provide feedback to the orchestrated operation of one or moreDHSGs 510 a, 510 b. This information may include oil flow, porosity,temperature, pressure, viscosity, and/or other characteristics asobserved from one or more wells in the field. In one embodiment, one ormore master systems 500 may be used.

In one embodiment, the DHSGs 510 a, 510 b may be positioned in separatewells. In one embodiment, the DHSGs 510 a, 510 b may be position in thesame well. For example, the DHSGs 510 a, 510 b may be disposed in aserial configuration, one above the other or spaced apart for injectingfluids into one or more reservoirs. For further example, the DHSGs 510a, 510 b may be disposed in separate wells or branches of a multilateralwell (e.g. a primary borehole having one or more secondary or lateralboreholes extending from the primary borehole) for injecting fluids intoone or more reservoirs. One or more DHSGs 510 a, 510 b may be positionedin the primary borehole and/or secondary boreholes extending from theprimary borehole.

The measurement and control systems 100-500 described herein may beoperable to conduct one or more diagnostic tests, and perform one ormore corrective actions based on the diagnostic tests. The measurementand control systems 100-500 may monitor the wellbore operations fordeterioration or failing of one or more components of the systems, suchas the steam generator, the umbilical, the well head, and/or surfaceequipment, and may then apply corrective measures to prevent systemand/or operation failure. In this manner, the measurement and controlsystems 100-500 may predict potential malfunctions and/or maintenancerequirements, and may be utilized as a preventative maintenance tool.

In one embodiment, the measurement and control systems 100-500 may beprogrammed with one or more maintenance schedules of one or morecomponents of the systems, such as the steam generator, the umbilical,the well head, and/or surface equipment, and may provide an indicationof a scheduled maintenance before a component fails or reaches the endof its operating life. In one embodiment, the measurement and controlsystems 100-500 may monitor operational parameters such as temperature,pressure, fuel/oxygen/water/steam type and purity, and wellboreenvironment conditions (e.g. acidity, gas cut, etc.), all of which willaffect the performance and life of the components of the systems andwellbore equipment. In one embodiment, the measurement and controlsystems 100-500 may optimize the performance of the system componentsand wellbore operations to maximize the life of the system componentsand/or wellbore production.

One or more of the embodiments of the systems 100, 200, 300, 400, and500 described herein may be combined, interchanged, and/or duplicated toform additional measurement and control systems.

While the foregoing is directed to embodiments of the invention, otherand further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. A measurement and control system, comprising: a downhole steamgenerator (DHSG); and a surface control unit functioning to receive ameasurement signal from the DHSG, wherein the surface control unitfunctions to control operation of the DHSG in response to themeasurement signal.
 2. The system of claim 1, wherein the surfacecontrol unit is in communication with the DHSG via one or more umbilicallines, wherein the umbilical lines comprise at least one transmissionline for transmitting the measurement signal from the DHSG to thesurface control unit.
 3. The system of claim 2, wherein the umbilicallines comprise at least one transmission line for transmitting a controlsignal from the surface control unit to the DHSG to adjust the operationof the DHSG.
 4. The system of claim 3, further comprising a downholecontrol unit functioning to receive at least one measurement from theDHSG and convert the measurement into the measurement signal that iscommunicated to the surface control unit.
 5. The system of claim 4,wherein the downhole control unit functions to generate a control signalbased on the at least one measurement and communicate the control signalto the surface control unit to adjust the operation of the DHSG.
 6. Thesystem of claim 5, wherein the surface control unit changes one or moreparameters of at least one process fluid, gas, or mixture supplied tothe DHSG based on the control signal generated by the downhole controlunit.
 7. The system of claim 6, wherein the downhole control unitchanges one or more parameters of at least one process fluid, gas, ormixture supplied to the DHSG based on the at least one measurement orbased on a control signal sent from the surface control unit in responseto the measurement signal.
 8. The system of claim 1, wherein the surfacecontrol unit functions to receive oilfield data and control operation ofthe DHSG in response to the oilfield data.
 9. The system of claim 1,further comprising a plurality of surface control units controlled by amaster control unit, wherein each surface control unit controlsoperation of a DHSG.
 10. The system of claim 9, wherein the mastercontrol unit functions to receive oilfield data and control operation ofthe surface control units in response to the oilfield data.
 11. A methodof operating a measurement and control system, comprising: monitoring anoperational characteristic of a downhole steam generator (DHSG) using asurface control unit; receiving a measurement signal corresponding tothe operational characteristic; and controlling operation of the DHSG inresponse to the measurement signal.
 12. The method of claim 11, furthercomprising receiving the measurement signal via at least onetransmission line of an umbilical that is connected to the DHSG and thesurface control unit.
 13. The method of claim 12, further comprisingtransmitting a control signal from the surface control unit to the DHSGvia at least one transmission line of the umbilical to adjust theoperation of the DHSG.
 14. The method of claim 13, further comprisingreceiving at least one measurement from the DHSG using a downholecontrol unit, and converting the measurement into the measurement signalthat is communicated to the surface control unit by the downhole controlunit.
 15. The method of claim 14, wherein the downhole control unitgenerates a control signal based on the at least one measurement andcommunicates the control signal to the surface control unit to adjustthe operation of the DHSG.
 16. The method of claim 15, furthercomprising changing one or more parameters of at least one processfluid, gas, or mixture supplied to the DHSG based on the control signalgenerated by the downhole control unit.
 17. The method of claim 16,further comprising changing one or more parameters of at least oneprocess fluid, gas, or mixture supplied to the DHSG based on the atleast one measurement or based on a control signal sent from the surfacecontrol unit in response to the measurement signal.
 18. The method ofclaim 11, further comprising receiving oilfield data using the surfacecontrol unit, and controlling operation of the DHSG in response to theoilfield data.
 19. The method of claim 11, further comprisingcontrolling a plurality of surface control units using a master controlunit, wherein each surface control unit controls operation of a DHSG.20. The method of claim 19, wherein the master control unit receivesoilfield data and controls operation of the surface control units inresponse to the oilfield data.
 21. A measurement and control system,comprising: a master control unit operable to receive oilfield data; aplurality of surface control units in communication with the mastercontrol unit, wherein each surface control unit controls operation of adownhole steam generator (DHSG), and wherein the master control unitfunctions to control operation of the DHSGs via remote setpointadjustments to the surface control units in response to the oilfielddata.
 22. The system of claim 21, further comprising a downhole controlunit operable to receive measurement signals from at least one of theDHSGs and communicate the signals to at least one of the surface controlunits.